Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation are complex. Typically, subterranean operations involve a number of different steps such as, for example, drilling the wellbore at a desired well site, treating the wellbore to optimize production of hydrocarbons, and performing the necessary steps to produce and process the hydrocarbons from the subterranean formation.
Modern oil field operations generally involve monitoring one or more parameters and conditions encountered downhole, including petrophysical properties such as the porosity and permeability of the rock comprising the formation, or the composition of fluids in the formation (e.g., formation fluids and components of formation fluids). Porosity may indicate, for example, the volume of oil or gas that may be present in the formation as a whole, while permeability may be used to assess the relative ease with which formation fluids (such as oil and gas within the formation) will flow into the well, that is, the productivity of the well.
Thus, during or after drilling, reservoirs are often evaluated to determine various properties of the formation and the hydrocarbons contained therein. These characteristics of a formation may be extrapolated from a small portion of the formation exposed during the drilling process. For example, data may be collected during drilling, well testing, logging, and coring operations. In many cases, rock samples from the formation (such as core samples or cuttings) may be the source of such data.
This information about the formation may be helpful in optimizing drilling operations (e.g., whether stimulation such as fracturing or acidization is necessary), assessing the well's productivity based upon permeability measurements, or other analyses. Because this information often impacts the operation of the well drilling process, it may be desirable to determine the formation information as quickly and efficiently as possible.
Conventional methods and equipment for assessing parameters such as fluid characterization, porosity, and permeability analyze each of those parameters using separate analytical processes. For example, a rock sample may be obtained, and all formation fluid may be washed from the sample and collected for characterization or other analysis. Then, separately, another fluid may be passed through the rock sample so as to obtain measurements of flow rate and/or pressure difference of the fluid passed over the rock sample (using, e.g., core flood equipment, permeability-measurement devices, and various other equipment). Also separately, porosity of the rock sample may be assessed by a conventional process and equipment, such as gas porosimeters (a helium/argon/carbon dioxide/nitrogen, or krypton), mercury injection, brine saturation, and pressure-transient plus decay methods, each of which include means of estimating total volume and pore volume of the sample. In some instances, accurate permeability and/or porosity measurements specific to hydrocarbons within the formation fluid may only be possible by rehabilitating the rock sample—that is, re-saturating it with natural or simulated formation water prior to running porosity and/or permeability tests, so as to accurately capture the effect of the formation water upon oil phase permeability and relative porosity. Consequently, operators may be forced to delay operations while these different analyses are taking place, which may cause various operational delays and added expenditures during the drilling process.
The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.